UNITED STATESSECURITIES AND EXCHANGE COMMISSIONWashington, D.C. 20549

FORM 10-Q

ý

QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934For the quarterly period ended June 30, 2008ORo

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934For the transition period
from                                    toCommission file number 1-10934


ENBRIDGE ENERGY PARTNERS, L.P.(Exact name of registrant as specified in its charter)

Delaware(State or other jurisdiction of
incorporation or organization)

39-1715850(I.R.S. Employer
Identification No.)1100 Louisiana
Suite 3300
Houston, TX 77002(Address of principal executive offices and zip code)(713) 821-2000(Registrant's telephone number, including area code)


Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act
of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the
past 90 days. Yes ý No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting
company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.

Large Accelerated Filer ý

Accelerated Filer oNon-Accelerated Filer o (Do not check if a smaller reporting company)

Smaller reporting company o


Indicate
by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange
Act). Yes o No ý

The Registrant had 59,838,834 Class A common units outstanding as of July 29, 2008.



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ENBRIDGE ENERGY PARTNERS, L.P.

TABLE OF CONTENTS

PART I. FINANCIAL INFORMATIONItem 1.

Financial StatementsConsolidated Statements of Income for the three and six month periods ended June 30, 2008 and 2007


3Consolidated Statements of Comprehensive Income for the three and six month periods ended June 30, 2008 and 2007


4Consolidated Statements of Cash Flows for the six month periods ended June 30, 2008 and 2007


5Consolidated Statements of Financial Position as of June 30, 2008 and December 31, 2007


6Notes to Consolidated Financial Statements


7Item 2.

Management's Discussion and Analysis of Financial Condition and Results of Operations


21Item 3.

Quantitative and Qualitative Disclosures About Market Risk


42Item 4.

Controls and Procedures


45PART II. OTHER
INFORMATIONItem 1.

Legal Proceedings


46Item 1A.

Risk Factors


46Item 6.

Exhibits


46Signatures


47Exhibits


In this report, unless the context requires otherwise, references to "we," "us," "our," or the "Partnership" are intended to mean Enbridge Energy
Partners, L.P. and its consolidated subsidiaries. This Quarterly Report on Form 10-Q contains forward-looking statements. These forward-looking statements are identified as
any statement that does not relate strictly to historical or current facts. They use words such as "anticipate," "believe," "continue," "estimate," "expect," "forecast," "intend," "may," "plan,"
"position," "projection," "strategy," "could," "should," "would," or "will" or the negative of those terms or other variations of them or by comparable terminology. In particular, statements,
expressed or implied, concerning future actions, conditions or events or future operating results or the ability to generate revenue, income or cash flow or to make distributions are forward-looking
statements. Forward-looking statements are not guarantees of performance. They involve risks, uncertainties and assumptions. Future actions, conditions or events and future results of operations may
differ materially from those expressed in these forward-looking statements. Many of the factors that will determine these results are beyond our ability to control or predict. For additional
discussion of risks, uncertainties and assumptions, see "Risk Factors" included in Part I, Item 1A of our Annual Report on Form 10-K for the fiscal year ended
December 31, 2007 and in Part II, Item 1A of our quarterly reports on Form 10-Q.

2

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PART IFINANCIAL INFORMATION

Item 1.    Financial Statements

ENBRIDGE ENERGY PARTNERS, L.P.        CONSOLIDATED STATEMENTS OF INCOME

Three months ended
June 30,

Six months ended
June 30,2008

2007

2008

2007(unaudited; in millions, except per unit amounts)Operating revenue

$
2,932.2

$
1,738.7

$
5,367.5

$
3,451.4Operating expensesCost of natural gas (Notes 9 and 10)


2,614.3


1,475.6


4,713.1


2,959.9Operating and administrative


121.8


105.1


238.5


202.8Power


31.3


27.3


69.6


57.4Depreciation and amortization


55.3


39.8


104.5


76.32,822.7


1,647.8


5,125.7


3,296.4Operating income


109.5


90.9


241.8


155.0Interest expense


51.4


21.5


79.0


46.8Other income


2.5


0.5


2.2


1.9Income before income tax expense


60.6


69.9


165.0


110.1Income tax expense


1.8


1.3


3.1


2.4Net income

$
58.8

$
68.6

$
161.9

$
107.7Net income allocable to limited partner units (Note 2)

$
48.4

$
59.3

$
140.2

$
90.7Net income per limited partner unit (basic and diluted) (Note 2)

$
0.50

$
0.69

$
1.49

$
1.10Weighted average limited partner units outstanding


96.3


86.5


94.4


82.2


The accompanying notes are an integral part of these consolidated financial statements.

3

---





ENBRIDGE ENERGY PARTNERS, L.P.        CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

Three months ended
June 30,

Six months ended
June 30,2008

2007

2008

2007(unaudited; in millions)Net income

$
58.8

$
68.6

$
161.9

$
107.7Other comprehensive income (loss), net of tax benefit of $1.0, $0, $2.8 and $1.3 (Notes 9 and 10)


(164.2
)

5.3


(190.5
)

(35.0
)Comprehensive income (loss)

$
(105.4
)
$
73.9

$
(28.6
)
$
72.7


The
accompanying notes are an integral part of these consolidated financial statements.

4

---





ENBRIDGE ENERGY PARTNERS, L.P.        CONSOLIDATED STATEMENTS OF CASH FLOWS

Six months ended June 30,2008

2007(unaudited; in millions)Cash provided by operating activitiesNet income

$
161.9

$
107.7Adjustments to reconcile net income to net cash provided by operating activities:Depreciation and amortization


104.5


76.3Derivative fair value losses (Notes 9 and 10)


30.1


12.6Other


10.9


(1.5
)Changes in operating assets and liabilities, net of cash acquired:Receivables, trade and other


(14.9
)

49.4Due from General Partner and affiliates


(6.3
)

5.0Accrued receivables


(265.3
)

43.5Inventory (Note 4)


(21.3
)

(3.9
)Current and long term other assets (Notes 9 and 10)


(2.8
)

(4.5
)Due to General Partner and affiliates


18.9


19.7Accounts payable and other (Notes 3, 9 and 10)


2.8


(14.5
)Accrued purchases


258.7


(42.4
)Interest payable


13.8


5.3Property and other taxes payable


4.8


6.0Settlement of interest rate derivatives (Note 10)


(22.1
)

Net cash provided by operating activities


273.7


258.7Cash used in investing activitiesAdditions to property, plant and equipment


(672.1
)

(891.5
)Changes in construction payables


(40.8
)

87.2Other


(5.4
)

(1.1
)Net cash used in investing activities


(718.3
)

(805.4
)Cash provided by financing activitiesNet proceeds from unit issuances (Note 7)


221.8


628.8Distributions to partners (Note 7)


(137.0
)

(115.8
)Net repayments under Credit Facility (Note 6)


(150.0
)

Net repayments of commercial paper (Note 6)


(168.6
)

(46.5
)Net proceeds from Senior Note issuances (Note 6)


790.2


Net cash provided by financing activities


556.4


466.5Net increase (decrease) in cash and cash equivalents


111.8


(80.2
)Cash and cash equivalents at beginning of year


50.5


184.6Cash and cash equivalents at end of period

$
162.3

$
104.4


The
accompanying notes are an integral part of these consolidated financial statements.

5

---





ENBRIDGE ENERGY PARTNERS, L.P.        CONSOLIDATED STATEMENTS OF FINANCIAL POSITION

June 30,
2008

December 31,
2007(unaudited; dollars in millions)ASSETSCurrent assetsCash and cash equivalents (Note 3)

$
162.3

$
50.5Receivables, trade and other, net of allowance for doubtful accounts of $1.8 in 2008 and $1.9 in 2007


174.2


157.8Due from General Partner and affiliates


33.5


27.2Accrued receivables


864.1


598.8Inventory (Note 4)


131.9


110.6Other current assets (Notes 9 and 10)


10.1


14.81,376.1


959.7Property, plant and equipment, net (Note 5)


6,128.2


5,554.9Goodwill


256.5


256.5Intangibles, net


90.8


91.5Other assets, net (Notes 9 and 10)


35.5


29.0$
7,887.1

$
6,891.6LIABILITIES AND PARTNERS' CAPITALCurrent liabilitiesDue to General Partner and affiliates

$
64.7

$
45.8Accounts payable and other (Notes 3, 8, 9 and 10)


460.2


400.4Accrued purchases


862.5


603.8Interest payable


34.7


20.9Property and other taxes payable


27.3


22.5Current maturities of long term debt


231.0


31.01,680.4


1,124.4Long term debt (Note 6)


3,146.6


2,862.9Notes payable to affiliate


130.0


130.0Other long-term liabilities (Notes 8, 9 and 10)


302.4


202.85,259.4


4,320.1Commitments and contingencies (Note 8)Partners' capital (Note 7)Class A common units (59,838,834 at June 30, 2008 and 55,238,834 at December 31, 2007)


1,523.4


1,340.7Class B common units (3,912,750 at June 30, 2008 and December 31, 2007)


77.1


72.9Class C units (18,767,526 at June 30, 2008 and 18,073,367 at December 31, 2007)


900.7


874.1i-units (14,070,848 at June 30, 2008 and 13,564,086 at December 31, 2007)


542.4


515.3General Partner


69.0


62.9Accumulated other comprehensive loss (Notes 9 and 10)


(484.9
)

(294.4
)2,627.7


2,571.5$
7,887.1

$
6,891.6


The accompanying notes are an integral part of these consolidated financial statements.

6

---





ENBRIDGE ENERGY PARTNERS, L.P.    NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

1.     BASIS OF PRESENTATION

The accompanying unaudited interim consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United
States of America for interim consolidated financial information and with the instructions to Form 10-Q and Rule 10-01 of Regulation S-X.
Accordingly, they do not include all the information and footnotes required by accounting principles generally accepted in the United States of America for complete consolidated financial statements.
In the opinion of management, they contain all adjustments, consisting only of normal recurring adjustments, which management considers necessary to present fairly our financial position as of
June 30, 2008 and December 31, 2007; the results of operations for the three and six month periods ended June 30, 2008 and 2007; and our cash flows for the six month periods ended
June 30, 2008 and 2007. We derived the Consolidated Statement of Financial Position as of December 31, 2007, from the audited financial statements included in our 2007 Annual Report on
Form 10-K. The results of operations for the three and six month periods ended June 30, 2008, should not be taken as indicative of the results to be expected for the full
year due to seasonality
of portions of the natural gas business, timing and completion of our construction projects, maintenance activities and the impact of forward natural gas prices and differentials on certain derivative
financial instruments that are accounted for using mark-to-market accounting. The interim consolidated financial statements should be read in conjunction with our consolidated
financial statements and notes thereto presented in our Annual Report on Form 10-K for the fiscal year ended December 31, 2007.

Comparative Amounts

We have made reclassifications to the amounts reported in our prior year consolidated statement of financial position and our
consolidated statements of cash flows to conform to our current year presentation. We reclassified $2.8 million of "Environmental liabilities" to "Other long-term liabilities" in
our December 31, 2007 consolidated statement of financial position. We also reclassified $2.3 million for changes in the balance of "Current income tax payable" to "Property and other
taxes payable" on our consolidated statements of cash flows.

2.     NET INCOME PER LIMITED PARTNER UNIT

Net income per limited partner unit is computed by dividing net income, after deducting our allocation to our general partner, Enbridge Energy
Company, Inc. (the "General Partner"), by the weighted average number of our limited partner units outstanding. The General Partner's allocation is equal to an amount based upon its general
partner interest, adjusted to reflect an amount equal to its incentive distributions and an amount required to reflect depreciation on the General Partner's historical

7

---



cost
basis for assets contributed on formation of the Partnership. We have no dilutive securities. Net income per limited partner unit was determined as follows:

Three months ended
June 30,

Six months ended
June 30,2008

2007

2008

2007(unaudited; in millions, except per unit amounts)Net income

$
58.8

$
68.6

$
161.9

$
107.7Allocations to the General Partner:Net income


(1.1
)

(1.4
)

(3.2
)

(2.2
)Incentive distributions to the General Partner


(9.2
)

(7.9
)

(18.4
)

(14.7
)Historical cost depreciation adjustments


(0.1
)




(0.1
)

(0.1
)(10.4
)

(9.3
)

(21.7
)

(17.0
)Net income allocable to limited partner units

$
48.4

$
59.3

$
140.2

$
90.7Net income per limited partner unit (basic and diluted)

$
0.50

$
0.69

$
1.49

$
1.10Weighted average limited partner units outstanding


96.3


86.5


94.4


82.2


3.     CASH AND CASH EQUIVALENTS

We extinguish liabilities when a creditor has relieved us of our obligation, which occurs when our financial institution honors a check that the creditor has
presented for payment. Accordingly, obligations for which we have issued check payments that have not yet been presented to the financial institution, in the amounts of approximately
$46.5 million at June 30, 2008 and $38.5 million at December 31, 2007, are included in "Accounts payable and other" on our consolidated statements of financial position.

4.     INVENTORY

Inventory is comprised of the following:

June 30,
2008

December 31,
2007(in millions)Materials and supplies

$
3.9

$
3.9Liquids inventory


28.1


6.7Natural gas and natural gas liquids inventory


99.9


100.0$
131.9

$
110.6


8

---



5.     PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment is comprised of the following:

June 30,
2008

December 31,
2007(in millions)Land

$
14.3

$
14.3Rights-of-way


476.8


345.8Pipelines


3,972.2


2,703.2Pumping equipment, buildings and tanks


1,045.7


854.7Compressors, meters, and other operating equipment


590.0


536.1Vehicles, office furniture and equipment


134.7


123.3Processing and treating plants


297.9


200.4Construction in progress


731.8


1,813.9Total property, plant and equipment


7,263.4


6,591.7Accumulated depreciation


(1,135.2
)

(1,036.8
)Property, plant and equipment, net

$
6,128.2

$
5,554.9


6.     DEBT

Credit Facility

In March 2008, we requested and received approval from the parties named as lenders to our Credit Facility for a one year extension of
the maturity date from April 4, 2012 to April 4, 2013.

At
June 30, 2008, we had $250 million outstanding under our Credit Facility at a weighted average interest rate of 2.86% and letters of credit totaling
$297.4 million. The amounts we may borrow under the terms of our Credit Facility are reduced by the principal amount of our commercial paper issuances and the balance of our letters of credit
outstanding. At June 30, 2008 we could borrow $602.6 million under the terms of our Credit Facility, determined as follows:

June 30,
2008(in millions)Total credit available under Credit Facility

$
1,250.0Less: Amounts outstanding under Credit Facility


(250.0
)Balance of letters of credit outstanding


(297.4
)Principal amount of commercial paper issuances


(100.0
)Total amount we could borrow at June 30, 2008

$
602.6


Individual
borrowings under the terms of our Credit Facility generally become due and payable at the end of each contract period, typically a period of three months or less. We have the
option to repay these amounts on a non-cash basis by net settling with the parties to our Credit Facility by contemporaneously borrowing at the then current rate of interest and repaying
the amounts due. During the six months ended June 30, 2008, we net settled borrowings of approximately $410 million on a non-cash basis.

Commercial Paper Program

We have a commercial paper program that provides for the issuance of up to $600 million of commercial paper that is supported by
our Credit Facility. We access the commercial paper market primarily to provide temporary financing for our operating activities, capital expenditures and acquisitions, at rates that are generally
lower than the rates available under our Credit Facility. At June 30, 2008 and

9

---



December 31,
2007, respectively, we had $99.8 million and $268.5 million of commercial paper outstanding, net of unamortized discount of $0.2 million and
$1.5 million, at weighted average interest rates of 3.09% and 5.36%. At June 30, 2008 we could issue an additional $500 million in principal amount under our commercial paper
program. The commercial paper we can issue is limited by the credit available under our Credit Facility.

We
have the ability and intent to refinance all of our commercial paper obligations on a long-term basis under our unsecured long-term Credit Facility.
Accordingly, such amounts have been classified as long-term debt in our accompanying consolidated statements of financial position.

Senior Notes

In April 2008, we issued and sold in a private offering $400 million in principal amount of our 6.5% Notes due April 15,
2018 and $400 million in principal amount of our 7.5% Notes due April 15, 2038, which we collectively refer to as the Notes. We received net proceeds from the offering of approximately
$790.2 million after initial purchasers' discounts and payment of offering expenses. We used a portion of the proceeds we received from this offering to repay outstanding issuances of
commercial paper and borrowings under our Credit Facility that we had previously used to finance a portion of our capital expansion projects. We temporarily invested the remaining proceeds for use in
future periods to fund additional expenditures under our capital expansion programs. The Notes do not contain any covenants restricting our issuance of additional indebtedness and rank equally with
all of our other existing and future unsecured and unsubordinated indebtedness. Interest on the Notes is payable on April 15th and October 15th of each year and we may
redeem the Notes for cash in whole or in part at any time, at our option. Pursuant to a registration rights agreement we agreed to file, and have filed in July 2008, a registration statement with the
Securities and Exchange Commission ("SEC") offering to exchange the Notes for registered notes with similar principal amounts and terms.

7.     PARTNERS' CAPITAL

The following table sets forth the distributions, as approved by the Board of Directors of Enbridge Energy Management, L.L.C. ("Enbridge Management") during the
six months ended June 30, 2008:

Distribution
Declaration
Date

Distribution
Payment Date

Record Date

Distribution
per Unit

Cash
available for
distribution

Amount of
Distribution
of i-units to
i-unit
Holders(1)

Amount of
Distribution
of Class C
units to
Class C unit
Holders(2)

Retained
from
General
Partner(3)

Distribution
of CashApril 28, 2008

May 15, 2008

May 7, 2008

$
0.950

$
102.2

$
13.1

$
17.5

$
0.6

$
71.0January 28, 2008

February 14, 2008

February 6, 2008

$
0.950

$
96.7

$
12.9

$
17.2

$
0.6

$
66.0


---

Issuance of Class A Common Units

On March 3, 2008, we issued and sold 4.6 million Class A common units, including 0.6 million units from the
over-allotment option that was exercised by the underwriters, at a price to the public of $49.00 per unit, for proceeds of approximately $217.2 million, net of underwriters'
discounts, commissions and issuance costs. In addition, our general partner
contributed approximately $4.6 million to us to maintain its two percent general partner interest. We used the proceeds from this offering to partially reduce outstanding commercial paper we
issued and amounts we previously borrowed under our Credit Facility to finance a portion of our capital expansion projects. We invested a portion of the proceeds for use in future periods to fund
additional expenditures under our capital expansion projects.

10

---



8.     COMMITMENTS AND CONTINGENCIES

Environmental Liabilities

We are subject to federal and state laws and regulations relating to the protection of the environment. Environmental risk is inherent
to liquid hydrocarbon and natural gas pipeline operations and we could, at times, be subject to environmental cleanup and enforcement actions. We manage this environmental risk through appropriate
environmental policies and practices to minimize any impact our operations may have on the environment. To the extent that we are unable to recover environmental liabilities associated with the
Lakehead system assets through insurance, the General Partner has agreed to indemnify us from and against any costs relating to environmental liabilities associated with the Lakehead system assets
prior to the transfer to us in 1991. This excludes any liabilities resulting from a change in laws after such transfer. We continue to voluntarily investigate past leak sites on our systems for the
purpose of assessing whether any remediation is required in light of current regulations, and to date, no material environmental risks have been identified.

As
of June 30, 2008 and December 31, 2007, we have recorded $4.5 million and $3.4 million, respectively, in "Accounts payable and other" and
$3.0 million and $2.8 million, respectively, in "Other long-term liabilities," primarily to address remediation of contaminated sites, asbestos containing materials,
management of hazardous waste material disposal, and outstanding air quality measures for certain of our liquids and natural gas assets.

Legal Proceedings

We are a participant in various legal proceedings arising in the ordinary course of business. Some of these proceedings are covered, in
whole or in part, by insurance. We believe that the outcome of all these proceedings will not, individually or in the aggregate, have a material adverse effect on our financial condition.

9.     FAIR VALUE MEASUREMENTS

We adopted the provisions of Statement of Financial Accounting Standards No. 157,Fair Value Measurement,
or SFAS No. 157, as of January 1, 2008. SFAS No. 157 provides guidance for determining fair value and requires increased disclosure regarding the inputs to valuation techniques
used to measure fair value. SFAS No. 157 defines fair value as an exit price representing the expected amount we would receive to sell an asset or pay to transfer a liability in an orderly
transaction with market participants at the measurement date. We apply the provisions of SFAS No. 157 to fair values we report for our derivative instruments and annual disclosures associated
with the fair values of our outstanding indebtedness.

We
utilize a mid-market pricing convention for valuation as a practical expedient for assigning fair value to our derivative assets and liabilities. In the case of our
liabilities, our nonperformance risk is considered in the valuation, based upon the ratings assigned to our debt obligations by the nationally recognized statistical ratings organizations. We present
the fair value of our derivative contracts net of cash paid or received pursuant to collateral agreements on a net-by-counterparty basis in our consolidated statements of
financial position when we believe a legal right of setoff exists under an enforceable netting agreement. Our credit exposure for over-the-counter derivatives is directly with
our counterparty and continues until the maturity or termination of the contracts. When appropriate, valuations are adjusted for various factors such as credit and liquidity considerations.

SFAS
No. 157 establishes a hierarchy which prioritizes the inputs we use to measure fair value into three distinct categories based upon whether such inputs are observable in
active markets or unobservable. We classify assets and liabilities in their entirety based on the lowest level of input that is significant to the fair value measurement. Our methodology for
categorizing assets and liabilities that are measured at fair

11

---



value
pursuant to this hierarchy gives the highest priority to unadjusted quoted prices in active markets and the lowest level to unobservable inputs as outlined
below:



Derivative
contracts can be exchange-traded or over-the counter ("OTC"). We generally value exchange-traded derivatives within portfolios calibrated to market clearing levels
on a daily basis. We value OTC derivatives using broker information based on executed market transactions that we have corroborated with other observable market data. For OTC derivatives that trade in
liquid markets, such as generic forwards, swaps, and options, inputs can generally be verified and valuation does not involve significant management judgment.

Certain
OTC derivatives trade in less liquid markets with limited pricing information, and the determination of fair value for these derivatives is inherently more difficult. Such
instruments are classified within Level 3 of the fair value hierarchy. We include the fair value of financial assets and liabilities in Level 3 as a default due to limited market data or
in most cases, due to lacking binding broker quotes to corroborate pricing data as required by current interpretations of SFAS No. 157 Level 2 requirements. Financial assets and
liabilities that are categorized in Level 3 may later be reclassified to the Level 2 category at the point we are able to obtain sufficient binding market data or the interpretation of
Level 2 criteria is modified in practice to include non-binding market corroborated data.

The
following table sets forth by level within the fair value hierarchy, our financial assets and liabilities that were accounted for at fair value on a recurring basis as of
June 30, 2008. We classify financial assets and liabilities in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the
significance of a particular input to the fair value measurement

12

---



requires
judgment, and may affect the valuation of the financial assets and liabilities and their placement within the fair value hierarchy.

Fair Value at June 30, 2008Recurring fair value measures

Level 1

Level 2

Level 3

Total(in millions)Assets:Derivative instruments, net

$


$


$
10.1

$
10.1Liabilities:Derivative instruments, net


(338.8
)




(217.5
)

(556.3
)Total

$
(338.8
)
$


$
(207.4
)
$
(546.2
)


The
table below provides a summary of changes in the fair value of our Level 3 financial assets and liabilities for the six months ended June 30, 2008. As reflected in the
table, the net unrealized loss on Level 3 financial assets and liabilities was $91.3 million for the six months ended June 30, 2008, which resulted from forward price increases in
natural gas, natural gas liquids, or NGLs, and crude oil derivative instruments that we held at June 30, 2008.

Derivative
Instruments, net(in millions)Balance at January 1, 2008

$
(160.6
)Realized and unrealized net losses


(44.3
)Purchases and settlements


(2.5
)Transfer in (out) of Level 3


Balance at June 30, 2008

$
(207.4
)Change in unrealized net losses relating to instruments still held at June 30, 2008

$
(91.3
)


10.   DERIVATIVE FINANCIAL INSTRUMENTSCOMMODITY PRICE RISK

Our net income and cash flows are subject to volatility stemming from changes in commodity prices of natural gas, NGL, condensate and fractionation margins (the
relative price differential between NGL sales and the offsetting natural gas purchases). Our exposure to commodity price risk exists within our Natural Gas and Marketing segments. We use derivative
instruments including futures, forwards, swaps, options and other financial instruments with similar characteristics to manage the risks associated with market fluctuations in commodity prices, as
well as to reduce the volatility of our cash flows. Our formal hedging program provides a control structure and governance for our hedging activities specific to identified risks and time periods,
which are subject to the approval and monitoring by a committee of senior management. Based on our risk management policies, all of our derivative instruments are employed in connection with an
underlying asset, liability and/or forecasted transaction and are not entered into with the objective of speculating on interest rates or commodity prices. We have hedged a portion of our exposure to
the variability in future cash flows associated with forecasted natural gas and NGL sales and purchases through 2013 in accordance with our risk management policies.

Accounting Treatment

We record all derivative instruments in our consolidated financial statements at fair value pursuant to the provisions of Statement of
Financial Accounting Statement No. 133,Accounting for Deriviative Instruments and Hedging Activities, or SFAS No. 133, and the guidance
set forth in SFAS No. 157 as

13

---



discussed
in Note 9 above. We adjust our consolidated financial statements each period for changes in the fair value of our derivative instruments, which we refer to as "marking to market" or
"mark-to-market." For those derivative instruments that do not qualify for hedge accounting, we record all changes in fair market value through our consolidated statements of
income each period.

Under
the guidance of SFAS No. 133, if a derivative instrument does not qualify as a hedge, or is not designated as a hedge, the derivative instrument is adjusted to its fair
value each period with the increases and decreases in fair value recorded in our consolidated statements of income as increases and decreases in "Cost of natural gas" for our commodity-based
derivatives. Our cash flow is only impacted to the extent the actual derivative contract is settled by making or receiving a payment to or from the counterparty or by making or receiving a payment for
entering into a contract that exactly offsets the original derivative contract. Typically, we settle our derivative contracts when the physical transaction that underlies the derivative instrument
occurs.

If
a derivative instrument qualifies and is designated as a cash flow hedge, a hedge of a forecasted transaction or future cash flows, any unrealized
mark-to-market gain or loss is deferred in "Accumulated other comprehensive income" ("AOCI"), a component of Partners' Capital, until the underlying hedged transaction occurs.
To the extent that the hedge instrument is effective in offsetting the transaction being hedged, there is no impact to the income statement. At inception and on a quarterly basis, we formally assess
whether the hedge contract is highly effective in offsetting changes in cash flows of hedged items. Any ineffective portion of a cash flow hedge's change in fair value is recognized each period in
earnings. Realized gains and losses on derivative instruments that are designated as hedges and qualify for hedge accounting are included in "Cost of natural gas" in the period the hedged transaction
occurs. Gains and losses deferred in AOCI related to cash flow hedges, for which hedge accounting has been discontinued, remain in AOCI until the underlying physical transaction occurs unless it is
probable that the forecasted transaction will not occur by the end of the originally specified time period, or within an additional two-month period of time thereafter. Generally, our
preference is for our derivative instruments to receive hedge accounting treatment whenever possible, to mitigate the non-cash earnings volatility that arises from recording the changes in
fair value of our derivative instruments through earnings. To qualify for cash flow hedge accounting as set forth in SFAS No. 133, very specific requirements must be met in terms of hedge
structure, hedge objective and hedge documentation.

Non-Qualified Hedges

Many of our derivative instruments qualify for hedge accounting treatment under the specific requirements of SFAS No. 133.
However, we have four primary transaction types associated with our commodity derivative instruments where the hedge structure does not meet the requirements to apply hedge accounting. As a result,
these derivative instruments do not qualify for hedge accounting under SFAS No. 133 and are referred to as "non-qualified." Non-qualified derivative instruments are
marked-to-market each period with the change in fair value, representing unrealized gains and losses, included in "Cost of natural gas" in our consolidated statements of
income. These mark-to-market adjustments produce a degree of earnings volatility that can often be significant from period to period, but have no cash flow impact relative to
changes in market prices. The cash flow impact occurs when the underlying physical transaction takes place in the future and when the associated derivative instrument contract settlement is made.

The
four primary transaction types that do not qualify for hedge accounting are as follows:



14

---





In
each of the instances described above, the underlying physical purchase, storage and sale of natural gas and NGLs are accounted for on a historical cost or market basis rather than on
the mark-to-market basis we utilize for the derivative instruments employed to mitigate the commodity price risk associated with our storage and transportation assets. This
difference in accounting treatment between the derivative instrument and the underlying transaction (i.e., the derivative instruments are recorded at fair value while the physical transactions
are recorded at historical cost) can and has resulted in volatility in our reported

15

---



net
income, even though the economic margin is essentially unchanged from the date the transactions were consummated.

The
following table presents the unrealized gains and losses associated with changes in the fair value of our derivative instruments, which are recorded as an element of "Cost of natural
gas" for our commodity-based derivative instruments and "Interest expense" for our interest rate derivative instruments in our consolidated statements of income and disclosed as a reconciling item on
our consolidated statements of cash flows:

Three months ended
June 30,

Six months ended
June 30,Derivative fair value gains (losses)

2008

2007

2008

2007(in millions)Natural Gas segmentHedge ineffectiveness

$
0.7

$
0.2

$
(1.2
)
$
0.3Non-qualified hedges


(22.7
)

(2.8
)

6.0


(6.0
)MarketingNon-qualified hedges


(22.0
)

6.3


(34.9
)

(6.9
)Commodity derivative fair value gains (losses)


(44.0
)

3.7


(30.1
)

(12.6
)CorporateNon-qualified interest rate hedges


0.2








Derivative fair value gains (losses)

$
(43.8
)
$
3.7

$
(30.1
)
$
(12.6
)


De-designation and Settlement of Derivatives

We record the change in fair value of our cash flow hedges in AOCI until the derivative instruments are settled, at which time they are
reclassified from AOCI to earnings. Also included in AOCI at June 30, 2008 are unrecognized losses of approximately $1.8 million associated with cash flow hedges that were subsequently
de-designated. These losses are reclassified to earnings over the periods during which the originally hedged forecasted transactions affect earnings. For the three months and six months
ended June 30, 2008, we reclassified losses of $29.0 million and $60.3 million, respectively, from AOCI to "Cost of natural gas" on our consolidated statements of income for the
fair value of derivative instruments that were settled.

In
connection with our April 2008 issuance and sale of $800 million in principal amount of Notes, we paid $22.1 million to settle treasury locks we entered to hedge the
interest payments on a portion of these obligations through the maturity date of the Notes maturing in 2038. The $22.1 million is being amortized from AOCI to"Interest expense" over the
30-year term of the Notes.

Derivative Positions

Our derivative financial instruments are included at their fair values in our consolidated statements of financial position as follows:

June 30,
2008

December 31,
2007(in millions)Other current assets

$
4.0

$
6.5Other assets, net


1.8


6.4Accounts payable and other


(260.6
)

(165.5
)Other long-term liabilities


(291.4
)

(192.9
)$
(546.2
)
$
(345.5
)


16

---





The increase in our obligation associated with derivative activities is primarily due to an increase in forward and daily natural gas, NGL and condensate prices from December 31,
2007 to June 30, 2008. The Partnership's portfolio of derivative financial instruments is largely comprised of long-term fixed price natural gas and NGL sales and purchase
agreements.

We
present the fair value of our derivative contracts on a net-by-counterparty basis in our consolidated statements of financial position when we believe a legal
right of setoff exists under an enforceable netting agreement. Our credit exposure for over-the-counter derivatives is directly with our counterparty and continues until the
maturity or termination of the contract. When appropriate, valuations are adjusted for various factors such as credit and liquidity considerations.

The
table below summarizes our counterparty credit quality and exposures, in millions of dollars.

Counterparty Credit Quality*

June 30,
2008

December 31,
2007(in millions)AAA

$


$
AA


(352.4
)

(298.3
)A


(193.8
)

(47.2
)Lower than A





Total

$
(546.2
)
$
(345.5
)






11.   SEGMENT INFORMATION

Our business is divided into operating segments, defined as components of the enterprise, about which financial information is available and evaluated regularly
by our Chief Operating Decision Maker in deciding how resources are allocated and performance is assessed.

Each
of our reportable segments is a business unit that offers different services and products that is managed separately, since each business segment requires different operating
strategies. We have segregated our business activities into three distinct operating segments:



17

---





The
following tables present financial information about our business segments:

For the three months ended June 30, 2008Liquids

Natural Gas

Marketing

Corporate(1)

Total(in millions)Total revenue

$
189.2

$
2,280.7

$
1,474.2

$


$
3,944.1Less: Intersegment revenue


0.2


944.3


67.4





1,011.9Operating revenue


189.0


1,336.4


1,406.8





2,932.2Cost of natural gas





1,192.6


1,421.7





2,614.3Operating and administrative


41.3


77.1


2.3


1.1


121.8Power


31.3











31.3Depreciation and amortization


26.7


28.2


0.4





55.3Operating income


89.7


38.5


(17.6
)

(1.1
)

109.5Interest expense











51.4


51.4Other income











2.5


2.5Income before income tax expense


89.7


38.5


(17.6
)

(50.0
)

60.6Income tax expense











1.8


1.8Net income

$
89.7

$
38.5

$
(17.6
)
$
(51.8
)
$
58.8Capital expenditures (excluding acquisitions)

$
204.9

$
90.4

$


$
3.3

$
298.6


---

For the three months ended June 30, 2007Liquids

Natural Gas

Marketing

Corporate(1)

Total(in millions)Total revenue

$
129.4

$
1,384.4

$
954.3

$


$
2,468.1Less: Intersegment revenue





670.1


59.3





729.4Operating revenue


129.4


714.3


895.0





1,738.7Cost of natural gas





591.8


883.8





1,475.6Operating and administrative


40.6


60.9


1.9


1.7


105.1Power


27.3











27.3Depreciation and amortization


16.7


22.4


0.7





39.8Operating income


44.8


39.2


8.6


(1.7
)

90.9Interest expense











21.5


21.5Other income











0.5


0.5Income before income tax expense


44.8


39.2


8.6


(22.7
)

69.9Income tax expense











1.3


1.3Net income

$
44.8

$
39.2

$
8.6

$
(24.0
)
$
68.6Capital expenditures (excluding acquisitions)

$
270.2

$
219.2

$
0.3

$
2.5

$
492.2


---

18

---



As of and for the six months ended June 30, 2008Liquids

Natural Gas

Marketing

Corporate(1)

Total(in millions)Total revenue

$
346.2

$
4,154.8

$
2,673.0

$


$
7,174.0Less: Intersegment revenue


0.2


1,654.4


151.9





1,806.5Operating revenue


346.0


2,500.4


2,521.1





5,367.5Cost of natural gas





2,180.4


2,532.7





4,713.1Operating and administrative


78.8


152.0


4.6


3.1


238.5Power


69.6











69.6Depreciation and amortization


46.3


57.3


0.9





104.5Operating income


151.3


110.7


(17.1
)

(3.1
)

241.8Interest expense











79.0


79.0Other income











2.2


2.2Income before income tax expense


151.3


110.7


(17.1
)

(79.9
)

165.0Income tax expense











3.1


3.1Net income

$
151.3

$
110.7

$
(17.1
)
$
(83.0
)
$
161.9Total assets

$
3,460.5

$
3,652.4

$
549.5

$
224.7

$
7,887.1Capital expenditures (excluding acquisitions)

$
501.7

$
163.9

$


$
6.5

$
672.1


---

As of and for the six months ended June 30, 2007Liquids

Natural Gas

Marketing

Corporate(1)

Total(in millions)Total revenue

$
262.2

$
2,708.7

$
1,843.7

$


$
4,814.6Less: Intersegment revenue





1,238.9


124.3





1,363.2Operating revenue


262.2


1,469.8


1,719.4





3,451.4Cost of natural gas





1,255.0


1,704.9





2,959.9Operating and administrative


74.3


122.2


3.5


2.8


202.8Power


57.4











57.4Depreciation and amortization


33.1


42.4


0.8





76.3Operating income


97.4


50.2


10.2


(2.8
)

155.0Interest expense











46.8


46.8Other income











1.9


1.9Income before income tax expense


97.4


50.2


10.2


(47.7
)

110.1Income tax expense











2.4


2.4Net income

$
97.4

$
50.2

$
10.2

$
(50.1
)
$
107.7Total assets

$
2,279.0

$
3,074.0

$
353.1

$
170.4

$
5,876.5Capital expenditures (excluding acquisitions)

$
493.4

$
385.9

$
1.5

$
10.7

$
891.5


---

19

---



12.   SUBSEQUENT EVENT

Distribution to Partners

On July 28, 2008, the Board of Directors of Enbridge Management declared a distribution payable to our partners on
August 14, 2008. The distribution will be paid to unitholders of record as of August 6, 2008, of our available cash of $108.0 million at June 30, 2008, or $0.990 per common
unit. Of this distribution, $74.8 million will be paid in cash, $13.9 million will be distributed in i-units to our i-unitholder, $18.6 million will be
distributed in Class C units to the holders of our Class C units and $0.7 million will be retained from the General Partner in respect of the i-unit and Class C
unit distributions.

13.   RECENT ACCOUNTING PRONOUNCEMENTS NOT YET ADOPTED

Disclosures about Derivative Instruments and Hedging Activities

In March 2008, the Financial Accounting Standard Board, or FASB, issued Statement No. 161,Disclosures
about Derivative Instruments and Hedging Activities, which is effective for fiscal years and interim periods beginning after November 15, 2008. The statement requires
qualitative disclosures about a company's strategies and objectives for using derivatives, quantitative disclosures about fair value gains and losses on derivatives, and disclosures of
credit-risk-related contingent features in derivative instruments. We do not anticipate adopting the provisions of this pronouncement early. We do not expect our adoption of
this pronouncement to have a material affect on our financial statements other than modifications to our existing derivative disclosures to conform to the requirements set forth in the statement.

Calculation of Earnings Per Unit

In March 2008, the Emerging Issues Task Force, or EITF reached consensus on EITF Issue No. 07-4, Application of the Two-Class Method under FASB Statement
No. 128 to Master Limited Partnerships. The pronouncement prescribes the
manner in which a master limited partnership, or MLP, should allocate and present earnings per unit using the two-class method set forth in FASB Statement No. 128, Earning per Share. Under the
two-class method, current period earnings are allocated to the general
partner (including any embedded incentive distribution rights) and limited partners according to the distribution formula for available cash set forth in the partnership agreement. To the extent the
partnership agreement does not explicitly limit distributions to the general partner, any earnings in excess of distributions are to be allocated to the general partner and limited partners utilizing
the distribution formula for available cash specified in the partnership agreement. When current period distributions are in excess of earnings, the excess distributions are to be allocated to the
general partner and limited partners based on their respective sharing of losses specified in the partnership agreement for the period. EITF 07-4 is to be applied retrospectively
for all financial statements presented and is effective for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those fiscal years.
Earlier application is not permitted. We expect to adopt EITF 07-4 for our quarter ending March 31, 2009. We are currently evaluating the affect this pronouncement will have
on our present computation of earnings per unit.

20

---





Item 2.    Management's Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis of our financial condition and results of operations should be read together with our
consolidated financial statements and the accompanying notes included in "Item 1. Financial Statements" of this report.

Additionally,
this quarterly report on Form 10-Q should be read in conjunction with our Annual Report on Form 10-K for the year ended
December 31, 2007.

RESULTS OF OPERATIONSOVERVIEW

We provide services to our customers and returns for our unitholders primarily through the following
activities:



We
conduct our business through three business segments: Liquids, Natural Gas and Marketing. These segments are strategic business units established by senior management to facilitate
the achievement of our long-term objectives, to aid in resource allocation decisions and to assess operational performance.

The
following table reflects our operating income by business segment and corporate charges for the three and six month periods ended June 30, 2008 and 2007:

Three months ended
June 30,

Six months ended
June 30,2008

2007

2008

2007(unaudited; in millions)Operating IncomeLiquids

$
89.7

$
44.8

$
151.3

$
97.4Natural Gas


38.5


39.2


110.7


50.2Marketing


(17.6
)

8.6


(17.1
)

10.2Corporate, operating and administrative


(1.1
)

(1.7
)

(3.1
)

(2.8
)Total Operating Income


109.5


90.9


241.8


155.0Interest expense


51.4


21.5


79.0


46.8Other income


2.5


0.5


2.2


1.9Income tax expense


1.8


1.3


3.1


2.4Net Income

$
58.8

$
68.6

$
161.9

$
107.7


Several
types of arrangements in our Natural Gas and Marketing segments expose us to market risk associated with changes in commodity prices where we receive natural gas or NGLs in
return for the services we provide, or where we purchase natural gas or NGLs. We employ derivative financial instruments to reduce our exposure to natural gas and NGL price volatility. Some of these
derivative financial instruments do not qualify for hedge accounting under the provisions of Statement of Financial Accounting Standards No. 133,Accounting for
Derivative Instruments and Hedging Activities(SFAS No. 133), which can create volatility in our earnings that can be significant. However, these fluctuations in
earnings do not affect our cash flow. Cash flow is only affected when we settle the derivative instrument. Based on our risk management policies, all of our derivative instruments are employed in
connection with an underlying asset, liability and/or forecasted transaction and are not entered into with the objective of speculating on interest rates or commodity prices.

21

---



Summary Analysis of Operating Results

Liquids

Operating income from our Liquids segment increased by $44.9 million and $53.9 million to $89.7 million and
$151.3 million for the three and six months ended June 30, 2008, respectively, from the $44.8 million and $97.4 million for the same periods in 2007. The increase in
operating income of our Liquids segment is primarily due to the following:



Natural Gas

Operating income from our Natural Gas segment decreased to $38.5 million for the three months ended June 30, 2008 from
the $39.2 million for the same period of
2007. Operating income for the six months ended June 30, 2008 increased by $60.5 million to $110.7 million, from $50.2 million for the comparable period in 2007.

For
the three month period ended June 30, 2008, a $19.4 million increase in unrealized non-cash mark-to-market losses from our
derivative activities had a negative affect on the operating income of our Natural Gas business in relation to the same period of 2007. The following additional factors also affected the operating
income of our Natural Gas business:



For
the six months ended June 30, 2008, in addition to the factors discussed above, we had $4.8 million of unrealized, non-cash
mark-to-market gains, representing a $10.5 million improvement from the $5.7 million of losses we experienced in the same period of 2007. Additionally, operating
income for the six months ended June 30, 2008 was not affected by unscheduled maintenance at our Zybach processing facility and measurement losses which negatively affected operating income
during the same period of 2007.

Marketing

Operating income from our Marketing segment decreased by $26.2 million and $27.3 million to operating losses of
$17.6 million and $17.1 million for the three and six months
ended June 30, 2008, respectively, from operating income of $8.6 million and $10.2 million for the same periods in 2007. The operating results of our Marketing segment were
negatively affected by unrealized, non-cash, mark-to-market losses associated with derivative financial instruments that do not qualify for hedge accounting
treatment under SFAS No. 133. Partially offsetting these derivative losses is income derived from selling natural gas and NGLs into markets with more favorable pricing.

22

---



Derivative Transactions and Hedging Activities

We record all derivative instruments in our consolidated financial statements at fair market value pursuant to the requirements of SFAS
No. 133, and the guidance set forth in Statement of Financial Accounting Standards No. 157,Fair Value Measurement("SFAS
No. 157"). For those derivative instruments that do not qualify for hedge accounting, we record all changes in fair market value through our consolidated statements of income each period. Based
on our risk management policies, all of our derivative instruments are employed in connection with an underlying asset, liability and/or forecasted transaction and are not entered into with the
objective of speculating on interest rates or commodity prices.

The
fair values of all our derivative instruments reflect our best estimate of the price we would receive for selling an asset or pay to transfer a liability in an orderly transaction
with market participants at the measurement date. SFAS No. 157 defines how we are to determine fair value, establishes criteria for measuring fair value, and requires additional disclosures for
assets and liabilities that we report at fair value. We adopted the provisions of SFAS No. 157 prospectively beginning January 1, 2008, which did not affect our results of operations,
financial condition or cash flows due to the nature of our derivative instruments and our existing valuation methods.

Our
unrealized, non-cash mark-to-market losses of $43.8 million and $30.1 million for the three and six months ended June 30,
2008, are primarily the result of higher forward and daily prices of natural gas and NGLs relative to March 31, 2008 and December 31, 2007. The changes in fair value of our portfolio of
commoditybased derivative instruments that do not qualify for hedge accounting are a result of the volatility in the underlying prices for natural gas, NGLs and crude oil. We also had
$0.2 million of unrealized, non-cash mark-to-market gains in connection with interest rate derivatives that do not qualify for hedge accounting treatment
under SFAS No. 133. During the three months ended June 30, 2007 we had unrealized, mark-to-market gains that were the result of a decline in the forward and daily
market prices of natural and NGLs from March 31, 2007. However, during the six months ended June 30, 2007, increasing natural gas and
NGL prices from December 31, 2006, produced non-cash mark-to-market net losses of $12.6 million and negatively affected our operating results for that
period. Mark-to-market gains or losses create volatility in our operating results although the derivative instruments we have in place do not affect our cash flow until they
are settled. We expect these non-cash gains and losses to reverse in future periods as we settle the derivative instruments against the underlying physical transactions. We intend to
continue using derivative instruments to hedge our portfolio of natural gas and NGLs because of the economic benefit we derive from minimizing the volatility in our cash flows. Our continued use of
derivative instruments is likely to result in additional unrealized, non-cash gains or losses in the future.

The
following table presents the unrealized gains and losses associated with changes in the fair value of our derivative instruments, which are recorded as an element of "Cost of natural
gas" for our commodity-based derivative instruments and "Interest expense" for our interest rate derivative instruments in our consolidated statements of income and disclosed as a reconciling item on
our consolidated statements of cash flows:

Three months ended
June 30,

Six months ended
June 30,Derivative fair value gains (losses)

2008

2007

2008

2007(in millions)Natural Gas segmentHedge ineffectiveness

$
0.7

$
0.2

$
(1.2
)
$
0.3Non-qualified hedges


(22.7
)

(2.8
)

6.0


(6.0
)MarketingNon-qualified hedges


(22.0
)

6.3


(34.9
)

(6.9
)Commodity derivative fair value gains (losses)


(44.0
)

3.7


(30.1
)

(12.6
)CorporateNon-qualified interest rate hedges


0.2








Derivative fair value gains (losses)

$
(43.8
)
$
3.7

$
(30.1
)
$
(12.6
)


23

---



RESULTS OF OPERATIONSBY SEGMENT

Liquids

The following tables set forth the operating results and statistics of our Liquids segment assets for the periods presented:

Three months ended
June 30,

Six months ended
June 30,2008

2007

2008

2007(unaudited; in millions)Operating ResultsOperating revenues

$
189.0

$
129.4

$
346.0

$
262.2Operating and administrative


41.3


40.6


78.8


74.3Power


31.3


27.3


69.6


57.4Depreciation and amortization


26.7


16.7


46.3


33.1Operating expenses


99.3


84.6


194.7


164.8Operating Income

$
89.7

$
44.8

$
151.3

$
97.4Operating StatisticsLakehead system:United States(1)


1,235


1,138


1,246


1,192Province of Ontario(1)


322


340


351


338Total Lakehead system deliveries(1)


1,557


1,478


1,597


1,530Barrel miles (billions)


103


97


212


200Average haul (miles)


728


722


728


722Mid-Continent system deliveries(1)


237


248


244


245North Dakota system:Trunkline


107


92


105


89Gathering


6


6


5


6Total North Dakota system deliveries(1)


113


98


110


95Total Liquids Segment Delivery Volumes(1)


1,907


1,824


1,951


1,870


---

Three months ended June 30, 2008 compared with three months ended June 30, 2007

Our Liquids segment accounted for $89.7 million of operating income during the three months ended June 30, 2008, an
increase of $44.9 million from the $44.8 million generated during the same period in 2007. The favorable results are attributable to increased volumes transported on our Liquids systems
coupled with tariff increases that went into effect during 2007 and 2008, while actively managing our costs. The majority of the increase in delivery volumes is attributable to our Lakehead system;
however, our North Dakota system also realized increased delivery volumes.

Operating
revenue for the three months ended June 30, 2008 increased by $59.6 million to $189.0 million from $129.4 million for the same period in 2007. The
increase in operating revenue is due to the following:



24

---





We
implemented new tariffs in 2008 on our Lakehead system effective April 1, 2008 to reflect true-ups for the difference between estimated and actual cost and
throughput data for the prior year and our projected costs and throughput for 2008. The projected costs for 2008 include four projects: (1) the Southern Access mainline expansion,
(2) two Superior terminal tank projects, (3) two Griffith terminal tank projects and (4) the Clearbrook Manifold project. This filing increased the average tariff for crude oil
movements from the Canadian border to Chicago, Illinois, by approximately $0.34 per barrel, to an average of approximately $1.21 per barrel. We also implemented new tariffs on our North Dakota system
effective January 1, 2008 that are applicable for five years and are applied to all transportation routes with a destination of Clearbrook, Minnesota. Additionally, we increased the average
tariffs on all three of our Liquids systems in connection with the annual index rate ceiling
adjustment that went into effect July 1, 2007. The increases in average tariffs on all three Liquids systems coupled with longer hauls and transportation of more heavy crude oil contributed
approximately $43.3 million of additional operating revenue.

Average
delivery volumes on our Lakehead system increased approximately 5.3 percent, to 1.557 million Bpd during the three months ended June 30, 2008 from
1.478 million Bpd during the same period in 2007, contributing an additional $5.4 million to operating revenue. The increase in average deliveries on our Lakehead system is primarily
derived from increases of crude oil supplies from upstream production facilities associated with the ongoing development of the Alberta Oil Sands.

We
receive an allowance from our customers for the transportation of crude oil. We recognize revenue for the contractually agreed-upon allowance at the prevailing market
price for crude oil. The average prices of crude oil during the three months ended June 30, 2008 are substantially higher than the average prices for the same period of 2007. For example, the
average price of West Texas Intermediate crude oil has increased in excess of 90 percent for the three months ended June 30, 2008 as compared to the same period in 2007. As a result of
the increase in crude oil prices, we experienced an approximate $7.0 million increase in allowance oil revenues.

Oil
measurement adjustments occur as part of the normal operations associated with our Liquids systems. The three types of oil measurement adjustments that normally occur on our systems
include:



Operating
and administrative expenses for the Liquids segment increased $0.7 million for the three months ended June 30, 2008, compared with the same period in 2007. The
increase is driven primarily by

25

---



additional
workforce related costs associated with the operational, administrative, regulatory, and compliance support necessary for our growing systems, offset by decreases in oil measurement
adjustments and costs incurred in connection with our pipeline integrity program.

Power
costs increased $4.0 million in the three months ended June 30, 2008, compared with the same period in 2007, predominantly due to the higher delivery volumes coupled
with higher utility rates we are charged by our power suppliers. We have experienced a trend of increasing electricity rates from our power suppliers due to higher natural gas and coal costs.

The
increase in depreciation expense of $10.0 million is attributable to the additional assets we have placed in service during the last two quarters of 2007 and the first two
quarters of 2008, including the Southern Access Expansion stage one assets that we placed in service during the second quarter of 2008 along with the assets placed into service on our North Dakota and
Mid-Continent systems.

Six months ended June 30, 2008 compared with six months ended June 30, 2007

Our Liquids segment accounted for $151.3 million of operating income during the six months ended June 30, 2008,
representing a $53.9 million increase over the $97.4 million for the same period in 2007. The components comprising our operating income changed during the six months ended
June 30, 2008 compared with the six months ended June 30, 2007, primarily for the same reasons as noted above in the three-month analysis.

Future Prospects Update for Liquids

We and Enbridge Inc. ("Enbridge") are actively working with our customers to develop transportation options that will allow
Canadian crude oil greater access to markets throughout the United States. The following discussion provides an update to the status of projects we and Enbridge are constructing and should be read in
conjunction with the information
included in Item 7 of our Annual Report on Form 10-K for the year ended December 31, 2007.

Partnership
Projects

Southern Access

We continue to progress on the second and final stage of the expansion project which will provide additional upstream pumping capacity
and a new pipeline from Delavan to Flanagan, Illinois. Construction of this stage of the project commenced on June 1, 2008. We expect to complete this phase of the expansion by the end of the
first quarter of 2009. Completion of the total Southern Access expansion project will create a 454-mile pipeline with approximately 400,000 Bpd of incremental capacity on our
Lakehead system.

Alberta Clipper

The Alberta Clipper project involves construction of a new 36-inch diameter, 1,000 mile heavy crude oil pipeline from
Hardisty, Alberta to Superior, generally within or adjacent to our and Enbridge's existing rights-of-way. We will construct approximately 330 miles of the new pipeline
from the International Border near Neche, North Dakota to Superior and, at the request of our customers, we have revised the scope to also include a delivery connection at Clearbrook, Minnesota and an
additional tank at Superior. Alberta Clipper will have an initial capacity of 450,000 Bpd and allows for expansions up to 800,000 Bpd by adding pump stations. In addition, complementary
capacity on the Southern Access 42-inch pipeline from Superior to Flanagan will be obtained by installing additional pump stations. We anticipate that our share of the construction cost
for the United States segment of the project will approximate $1.2 billion. Alberta Clipper will be a common carrier line fully integrated with the Enbridge/Lakehead mainline systems for
tolling purposes. We and Enbridge are progressing on schedule with the project, which is expected to be in service in mid-2010.

26

---



North Dakota

The United States Geological Survey, or USGS, completed an assessment of the undiscovered oil and associated natural gas resources of
the Upper DevonianLower Mississippi Bakken formation in the United States portion of the Williston Basin and has determined there to be 3.0 to 4.3 billion barrels of
technologically recoverable oil. Regional producers in the Williston basin areas of Montana and North Dakota have expressed interest in further expansion of pipeline capacity on our North Dakota
system. As a result, we have commenced an approximate $0.15 billion additional expansion consisting of upgrades to existing pump stations, additional tankage, as well as extensive use of drag
reducing agents ("DRA") that are injected into the pipeline. This expansion of our North Dakota system, referred to as Phase VI, is expected to increase system capacity to 161,000 Bpd
from the 110,000 Bpd that is currently available. The commercial structure for this expansion is a cost-of-service based surcharge that will be added to the existing
tariff rates. The proposed surcharge is similar to the structure being used on the recently completed Phase V expansion project and is subject to approval from the Federal Energy Regulation
Commission ("FERC"). Regulatory applications have been filed and are pending approval.

Superior and Griffith Storage

Due to forecasted production increases of synthetic heavy crude oil that we anticipate will be transported on the Enbridge/Lakehead
mainline systems from Western Canada to Chicago, we are constructing additional crude oil storage tanks at Superior and Griffith to accommodate the anticipated volumes. We are building two tanks with
operational capacity of approximately 205,000 barrels each that are scheduled to be completed during 2008.

Enbridge
and Other Projects

Spearhead Pipeline

In another effort to provide shippers access to new markets, Enbridge acquired a pipeline that previously shipped crude oil from
Cushing to Chicago, Illinois. Enbridge reversed the pipeline, renamed it Spearhead, and began delivering Canadian crude oil to the major oil hub at Cushing in March 2006. Since then, the pipeline has
operated at or near its capacity of 125,000 Bpd. In the first half of 2007, Enbridge successfully concluded a binding open season for expansion of the pipeline to 190,000 Bpd, with
binding commitments for capacity of 30,000 Bpd. In December 2007, the FERC issued a favorable declaratory order effectively approving the tolling methodology and priority service for shippers
with binding commitments. The Spearhead pipeline is complementary to our Lakehead system as Western Canadian crude oil is carried on our Lakehead system as far as Chicago, and then transferred to the
Spearhead pipeline. The Spearhead pipeline expansion is expected to be in service in early 2009.

Southern Access Extension

In July 2006, Enbridge announced that it received support from shippers and the Canadian Association of Petroleum Producers ("CAPP")
for its 36-inch diameter Southern Access Extension pipeline from Flanagan, Illinois to Patoka, Illinois. The extension will broaden the reach of the Enbridge/Lakehead mainline system to
incremental markets accessible from the Patoka hub. This project is being undertaken by Enbridge, however, we will benefit from the incremental volumes moving through our Lakehead system to reach this
extension. Enbridge filed a petition for declaratory order with the FERC in October 2007, which was denied on May 7, 2008. Enbridge is currently working with shippers to develop a new
commercial structure for the pipeline.

Southern Lights

Following completion of a successful open season in 2006, Enbridge initiated its Southern Lights project to construct a diluent
pipeline from Chicago, Illinois to Edmonton, Alberta, Canada to meet the

27

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growing
demand for crude oil diluent required to transport the heavy oil and bitumen (a thick, tar-like form of oil) being produced in increasing volumes from the Alberta oil sands. The
project involves the exchange of a 156-mile section of pipeline we own, referred to as Line 13, for a similar section of a new pipeline to be constructed as part of the project. In
addition, this project involves a reconfiguration of our light crude mainline system which will provide an additional 45,000 Bpd of effective capacity at no cost to us. We expect to benefit
from increased heavy crude oil shipments, which will be facilitated by the diluent line.

In
February 2008, the National Energy Board ("NEB") issued its approval and in May 2008 the Canadian Government also issued its Governor In Council approval for the Canadian portion of
the Southern Lights project. Enbridge has filed the majority of necessary applications for the United States portion of the project with United States federal and state regulatory agencies. Enbridge
filed a petition for declaratory order with the FERC setting forth the rate structure for establishing tolls and the proposed swap of Line 13 discussed above, which the FERC approved in late
December 2007. In conjunction with our Southern Access project, the Southern Lights project has been allowed the right to exercise eminent domain for right-of-way in Illinois.
Construction and right-of-way acquisition related to this project continues in tandem with the Southern Access project. This project is expected to be placed in service in
2010.

Texas Access Pipeline

In December 2007, an open season was announced to solicit binding 15-year shipper commitments for the proposed Texas Access
Pipeline, which concluded on March 14, 2008. The open season did not obtain the required level of commitment, and as a result, Enbridge continues to work with potential shippers to review
alternatives to provide access for Western Canadian crude oil to the United States Gulf Coast.

Trailbreaker (formerly Eastern PADD II Access)

We and Enbridge are jointly developing plans to provide access for western Canadian crude oil to refineries along the United States
eastern seaboard and the United States gulf coast via the marine terminal at Portland, Maine. The Trailbreaker project involves the expansion and reversal of existing facilities to create a pipeline
route to Portland that is ready for use in 2010. Commercial terms for the project are being negotiated which will be subject to regulatory approvals in both the United States and Canada. Preliminary
estimates indicate the Partnership's portion of the project will approximate $0.3 billion (excluding capitalized interest).

28

---





Natural Gas

The following tables set forth the operating results of our Natural Gas segment assets and approximate average daily volumes of our
major systems in millions of British Thermal Units per day ("MMBtu/d") for the periods presented:

Three months ended
June 30,

Six months ended
June 30,2008

2007

2008

2007(unaudited; in millions)Operating ResultsOperating revenues

$
1,336.4

$
714.3

$
2,500.4

$
1,469.8Cost of natural gas


1,192.6


591.8


2,180.4


1,255.0Operating and administrative


77.1


60.9


152.0


122.2Depreciation and amortization


28.2


22.4


57.3


42.4Operating expenses


1,297.9


675.1


2,389.7


1,419.6Operating Income

$
38.5

$
39.2

$
110.7

$
50.2Operating Statistics (MMBtu/d)East Texas


1,454,000


1,190,000


1,425,000


1,162,000Anadarko


647,000


588,000


631,000


585,000North Texas


392,000


352,000


380,000


336,000UTOS


178,000


191,000


187,000


158,000MidLa


91,000


131,000


108,000


120,000AlaTenn


33,000


33,000


48,000


46,000Bamagas


36,000


114,000


69,000


115,000Other major intrastates


214,000


251,000


221,000


259,000Total(1)


3,045,000


2,850,000


3,069,000


2,781,000


---

Three months ended June 30, 2008 compared with three months ended June 30, 2007

Our Natural Gas segment contributed $38.5 million of operating income for the three months ended June 30, 2008, a
decrease of $0.7 million from the $39.2 million contributed in the corresponding period of 2007. The following primary factors affected the operating income of our Natural Gas business
for the three months ended June 30, 2008 as compared with the same period of 2007:



29

---





Revenue
for our Natural Gas business is derived from the fees or commodities we receive from the gathering, transportation, processing and treating of natural gas and NGLs for our
customers. We are exposed to fluctuations in commodity prices in the near term on 20 to 30 percent of the natural gas, NGLs and condensate we expect to receive as compensation for our services.
As a result of this unhedged commodity price exposure, our margins increase when the prices of these commodities are rising and decrease when the prices are declining. For the three months ended
June 30, 2008, we realized approximately $18 million of additional margin compared with the same period of 2007 primarily due to the higher prices we received from the sale of the
unhedged natural gas, NGLs and condensate that we received in-kind as compensation for our services.

We
enter into derivative financial instruments to hedge 70 to 80 percent of our near-term exposure to commodity prices associated with the in-kind
compensation we receive for our services. As a result of entering into these derivative instruments, we have largely fixed the amount of cash that we will pay and receive in the future when we sell
the processed natural gas, NGLs and condensate, even though the market price of these commodities will continue to fluctuate during that time. Many of these derivative financial instruments do not
qualify for hedge accounting which results in the derivative instrument being marked-to-market in our operating results. This accounting treatment produces unrealized
non-cash gains and losses in our reported operating results that can be significant during periods when the commodity price environment is volatile.

The
operating income of our Natural Gas segment for the three months ended June 30, 2008 was negatively affected by unrealized non-cash,
mark-to-market net losses of $22.0 million, representing an increase of $19.4 million from the $2.6 million of losses we recorded for the same period of
2007. We expect the net mark-to-market losses to be offset when the related physical transactions are settled. The following table depicts the affect that unrealized
non-cash mark-to-market gains and losses had on the operating results of our Natural Gas business for the three and six months ended June 30, 2008 and 2007:

Three months ended
June 30,

Six months ended
June 30,Derivative fair value gains (losses)

2008

2007

2008

2007(in millions)Natural Gas segmentHedge ineffectiveness

$
0.7

$
0.2

$
(1.2
)
$
0.3Non-qualified hedges


(22.7
)

(2.8
)

6.0


(6.0
)Derivative fair value gains (losses)

$
(22.0
)
$
(2.6
)
$
4.8

$
(5.7
)


We
adopted the provisions of Financial Accounting Standards Board Statement No. 157,Fair Value Measurements(SFAS No. 157)
effective January 1, 2008, which did not affect the operating results of our Natural Gas business, but did expand the disclosures we provide about how we determine the fair value of our
derivative instruments. Refer to the discussions included in Notes 9 and 10 of our consolidated financial statements included in Item 1 of this report and also to the discussions below
under "Derivative Activities" and the "Quantitative and Qualitative Disclosures about Market Risk" we include in Item 3 of this report for more information about our derivative activities.

The
increase in our average daily volumes is directly attributable to the significant investments that we have made to expand the capacity and service capability of our systems. We
completed the following projects during 2008 and the second half of 2007 which have contributed to the increase in average daily volumes and operating results of our major natural gas
systems:



30

---





With
the expansions we completed in 2007 and 2008 we are now able to provide additional gathering, processing, treating and transportation services for our customers which has
contributed to volume growth during the second quarter of 2008. Volume and revenue growth is also the result of additional wellhead supply contracts and continued robust drilling activity in the areas
served by our Natural Gas business, primarily the Bossier Trend and Barnett Shale areas. We expect the volumes on our major natural gas systems to continue increasing throughout the year as a result
of our investments to expand
the capacity of our systems to provide gathering, processing and transportation services to meet the needs of producers in the areas we serve.

Our
processing margins also continue to benefit from a favorable pricing environment. NGL prices continue to remain high relative to natural gas prices providing a favorable environment
for the production of NGLs from our processing assets. We also added approximately 120 MMcf/d of processing capacity on our Anadarko system in April 2007 and 75 MMcf/d on our North Texas
system in the second half of 2007. The added processing capacity provided us with the ability to generate additional processing margin from the natural gas we processed for our customers during the
second quarter of 2008. Our Zybach processing plant has also continued to operate at expected levels during the second quarter of 2008, which compares favorably with the second quarter of 2007 when we
experienced operational issues that reduced processing margins by approximately $3 million.

A
variable element of our Natural Gas segment's operating income is derived from the processing of natural gas under keep-whole arrangements that exist within our East Texas,
North Texas and Anadarko systems. Operating income derived from keep-whole processing arrangements for the three months ended June 30, 2008 was approximately $18 million,
representing an increase of $1 million from the approximate $17 million of operating income derived from keep-whole processing for the same period in 2007. The relatively
small change is a result of the improvement on our Anadarko system due to the addition of our Hidetown processing facility and the correction of the operational issues we experienced with our Zybach

31

---



processing
plant, both of which occurred in April 2007. We continue to experience a trend of replacing or renegotiating some of our existing keep-whole contracts with percent of liquids,
or POL, type contracts and other similar arrangements. This trend may reduce our exposure to commodity price risk along with a portion of the operating income we derive from processing natural gas
under keep-whole arrangements.

Operating
and administrative costs of our Natural Gas segment were $16.2 million greater for the three months ended June 30, 2008 than the three months ended
June 30, 2007, primarily as a result of increased workforce-related costs associated with the expansion of our systems, maintenance activities and other costs that are mostly variable with
volumes. Our general partner charges us the costs associated with employees and related benefits for personnel that are assigned to us or otherwise provide us with managerial and administrative
services. The portion of compensation and related costs we are charged is dependent upon such items as estimated time spent, miles of pipe and headcount. In addition we have experienced an increase in
outside contract labor cost, given the high demand and competitive rates within our industry as a result of pipeline expansions across the areas we serve.

Materials,
supplies and other costs along with repair and maintenance costs were higher predominantly due to the increase in volumes and expansion of our natural gas systems. Repair and
maintenance costs include compressor maintenance, downtime for routine and unscheduled maintenance, pipeline integrity costs and other similar items that have increased with the expansion of our
natural gas systems. We
expect workforce related costs in addition to materials, supplies and other cost to increase in relation to the increase in volumes of natural gas services we provide.

Depreciation
expense for our Natural Gas segment was higher in the second quarter of 2008 as compared the second quarter of 2007, as a result of the capital projects completed and placed
in-service during the first half of 2008 and the second half of 2007. We expect deprecation expense will be higher in 2008 as a result of the projects we completed and placed in service
throughout 2007 and the first half of 2008.

Six months ended June 30, 2008 compared with six months ended June 30, 2007

Our Natural Gas segment accounted for $110.7 million of operating income during the six months ended June 30, 2008,
representing a $60.5 million increase over the $50.2 million for the same period in 2007. The components comprising our operating income changed favorably during the six months ended
June 30, 2008 compared with the six months ended June 30, 2007, primarily for the same reasons noted above in our three-month analysis except for those items described below.

Natural
gas measurement losses occur as part of the normal operating conditions associated with our natural gas pipelines. The quantification and resolution of measurement losses is
complicated by several factors including varying qualities of natural gas in the streams gathered and processed through our systems, changes in weather, temperatures and variances in measurement that
are inherent in metering technologies. During the first six months of 2007, we identified operating conditions on our gathering systems which contributed to an increase in measurement losses. We have
since installed separator equipment to identify and reduce free-water in the natural gas streams, one of the underlying causes for the increase in measurement losses during 2007. As a
result of the steps we took in 2007 to address the increase in measurement losses, the measurement losses we have experienced during the six months ended June 30, 2008 are in-line
with our expectations.

Our
Zybach processing plant has continued to operate at expected levels during the first half of 2008, which compares favorably with the same period of 2007 when we had unscheduled
maintenance that reduced processing margins by approximately $11 million.

Operating
income for the six months ended June 30, 2008 was positively affected by the unrealized non-cash, mark-to-market net gains of
$4.8 million from our derivative activities, which is approximately

32

---



$10.5 million
more than the $5.7 million of losses we recorded for the same period of 2007. We expect the net mark-to-market gains and losses to be offset when
the related physical transactions are settled.

Future Prospects Update for Natural Gas

We continue to assess various expansion opportunities to pursue our strategy for growth. While we remain committed to making accretive
acquisitions in or near areas where we already operate or have a competitive advantage, we will continue to focus our efforts primarily on development of our existing pipeline systems. Although we
have successfully completed a majority of the significant expansion projects within our Natural Gas business, we are continually evaluating strategic opportunities to further expand the service
capabilities of our existing systems. We may, and have, pursued opportunities to divest any non-strategic natural gas assets as conditions warrant.

Results
of our natural gas gathering and processing business depend upon the drilling activities of natural gas producers in the areas we serve. During the second quarter of 2008,
increased production from active drilling in the areas where our gathering systems are located has contributed to our volume growth. We expect the growth trend in these areas to continue in the future
as evidenced by external production forecast and the strong rig counts and permitting in the areas served by our systems.

Marketing

The following table sets forth the operating results of our Marketing segment assets for the periods presented:

Three months ended
June 30,

Six months ended
June 30,2008

2007

2008

2007(unaudited; in millions)Operating ResultsOperating revenues

$
1,406.8

$
895.0

$
2,521.1

$
1,719.4Cost of natural gas


1,421.7


883.8


2,532.7


1,704.9Operating and administrative


2.3


1.9


4.6


3.5Depreciation and amortization


0.4


0.7


0.9


0.8Operating expenses


1,424.4


886.4


2,538.2


1,709.2Operating Income (Loss)

$
(17.6
)
$
8.6

$
(17.1
)
$
10.2


A
majority of the operating income of our Marketing segment is derived from selling natural gas received from producers on our Natural Gas segment pipeline assets to customers who need
natural gas. As a result of our natural gas system expansions and other initiatives, our Marketing business now has access to several additional downstream natural gas pipelines, which it can use to
transport natural gas to primary markets where it can be sold at more favorable prices.

We
adopted the provisions of SFAS No. 157 effective January 1, 2008, which did not affect the operating results of our Marketing business, but did expand the disclosures we
provide about how we determine the fair value of our derivative instruments. Refer to the discussions included in Notes 9 and 10 of our consolidated financial statements included in
Item 1 of this report and also to the discussions below under "Derivative Activities" and the "Quantitative and Qualitative Disclosures about Market Risk" we include in Item 3 of this
report for more information about our derivative activities.

Three months ended June 30, 2008 compared with three months ended June 30, 2007

The operating income of our Marketing segment declined to a loss of $17.6 million for the second quarter of 2008 from income of
$8.6 million for the corresponding period in 2007. Included in operating

33

---



income
for the second quarter of 2008 are approximately $22.0 million of unrealized, non-cash, mark-to-market losses associated with derivative financial
instruments that do not qualify for hedge accounting treatment under SFAS No. 133, as compared with the $6.3 million of unrealized mark-to-market gains for the
same period of 2007. The unrealized, mark-to-market losses for the three months ended June 30, 2008 result from increases in the forward and daily market prices of
natural gas from March 31, 2008. We expect these net mark-to-market losses to be offset when the related physical transactions are settled. Partially offsetting the
losses associated with the derivative activities of our Marketing business is income derived from selling natural gas and NGLs into markets with more favorable pricing.

The
operating and administrative expenses of our Marketing business were slightly more in the quarter ended June 30, 2008 as compared with the same period of 2007 due to
additional workforce related costs associated with the employees and related benefits for personnel that are assigned to us or otherwise provide us with managerial and administrative services.

Six months ended June 30, 2008 compared with six months ended June 30, 2007

Similar to the three month analysis, operating income of our Marketing segment declined to a loss of $17.1 million for the six
month period ended June 30, 2008 from income of $10.2 million for the corresponding period in 2007. Included in operating income for the first six months of 2008 are approximately
$34.9 million of unrealized, non-cash, mark-to-market losses associated with derivative financial instruments that do not qualify for hedge accounting
treatment under SFAS No. 133, which are $28.0 million greater than the $6.9 million of unrealized mark-to-market losses for the comparable period of 2007.
The unrealized, mark-to-market losses for the six months ended June 30, 2008 result from increases in the forward and daily market prices of natural gas from
December 31, 2007. Partially offsetting the losses associated with the derivative activities of our Marketing business is income derived from selling natural gas and NGLs into markets with more
favorable pricing. We expect these net mark-to-market losses to be offset when the related physical transactions are settled.

The
operating and administrative expenses of our Marketing business are slightly more in the six months ended June 30, 2008 as compared with the same period of 2007 due to
additional workforce related costs associated with the employees and related benefits for personnel that are assigned to us or otherwise provide us with managerial and administrative services.

Corporate

Interest expense was $51.4 million and $79.0 million for the three months and six months ended June 30, 2008,
compared with $21.5 million and $46.8 million for the corresponding periods in 2007. The increases are primarily the result of higher weighted average debt balance associated with the
following debt issuances:



Our
weighted average interest rate is 6.2% for the three months and 6.1% for the six months ended June 30, 2008 as compared with our weighted average interest rates of 6.0% and
5.9% for the same periods in 2007.

34

---





Further contributing to the increase in interest expense is the $4.5 million decrease in interest capitalized to our construction projects in the three months ended
June 30, 2008 from the same period in 2007. Conversely, the increase in interest expense in the first six months of 2008 was offset by an additional $6.1 million of capitalized interest
when compared to the same period in 2007. For the three months and six months ended June 30, 2008 and 2007, our interest cost is comprised of the following:

Three months ended
June 30,

Six months ended
June 30,2008

2007

2008

2007(unaudited; in millions)Interest expense

$
51.4

$
21.5

$
79.0

$
46.8Interest capitalized


5.9


10.4


25.0


18.9Interest cost incurred

$
57.3

$
31.9

$
104.0

$
65.7


LIQUIDITY AND CAPITAL RESOURCES

General

We believe that our ability to generate cash flow, in addition to our access to capital, is sufficient to meet the demands of our
current and future operating and investment needs. Our primary cash requirements consist of normal operating expenses, capital expenditures for our expansion projects, maintenance capital
expenditures, debt service payments, distributions to our partners, acquisitions of new assets and businesses, and payments associated with our derivative transactions. Short-term cash
requirements, such as operating expenses, maintenance capital expenditures debt service payments and quarterly distributions to our partners, are expected to be funded by our operating cash flows.
Margin requirements associated with our derivative transactions are generally supported by letters of credit issued under our Credit Facility. We expect to fund long-term cash requirements
for expansion projects and acquisitions from several sources, including cash flows from operating activities, borrowings under our commercial paper program, our Credit Facility, and the issuance of
additional equity and debt securities. Our ability to complete future debt and equity offerings and the timing of any such offerings will depend on various factors, including prevailing market
conditions, interest rates, our financial condition and credit rating at the time.

Our
current business strategy emphasizes developing and expanding our existing Liquids and Natural Gas businesses with less focus on acquisitions. Although the internal growth projects
we have planned require significant expenditures of capital over the next several years, since the beginning of 2007, we have raised in excess of $2.2 billion through the issuance of a balanced
combination of debt and equity securities to fund these projects. We expect to use the same measured approach to fund the remaining expenditures from additional issuances of partnership capital and
long-term debt. Our planned internal growth projects continue to require us to bear the cost of constructing these new assets before we begin to realize a return on them.

Capital Resources

Equity and Debt Securities

Execution of our growth strategy and completion of our planned construction projects contemplate our accessing the public and private
equity and credit markets to obtain the capital necessary to fund these projects. In March 2008, we obtained approximately $221.8 million of cash from the public issuance and sale of
4.6 million of our Class A common units at a price to the public of $49.00 per unit, which consisted of $217.2 million of net proceeds, after payment of underwriters' discounts,
commissions and offering expenses and a contribution of $4.6 million from our general partner to maintain its two percent general partner interest. Additionally, in early April 2008, we
completed the private issuance and sale of our

35

---



$400 million
Notes due 2018 and our $400 million Notes due 2038 for net proceeds of approximately $790.2 million, after payment of initial purchasers' discounts and offering
expenses. The Notes due 2018 bear interest at the rate of 6.50% and the Notes due 2038 bear interest at the rate of 7.50%. We used a portion of the proceeds from these offerings to repay outstanding
issuances of commercial paper and borrowings under our Credit Facility, which we had previously used to finance a portion of our capital expansion projects. We temporarily invested the remaining
proceeds for use in future periods to fund additional expenditures under our capital expansion programs.

Available Credit

A significant source of our liquidity is provided by the commercial paper market and our Credit Facility. We have a $600 million
commercial paper program that is supported by our long-term Credit Facility, which we access primarily to provide temporary financing for our operating activities, capital expenditures and
acquisitions, at rates that are generally more competitive than the rates available under our Credit Facility.

United
States credit markets in the second quarter of 2008 continue to remain volatile despite actions taken by United States and foreign regulators. Investors have continued to seek
high-quality fixed income securities, favoring United States government securities over corporate issues. Although the credit ratings assigned to our senior unsecured debt securities by
the nationally recognized statistical ratings organizations are considered "investment grade," we may at times experience difficulty accessing the commercial paper and long-term credit
markets due to current economic conditions. Despite the continuing weakness in the United States credit markets, we have sufficient available liquidity to manage our capital requirements into
2009.

Credit Facility

In March 2008, we requested and received approval from the parties named as lenders to our Credit Facility for a one year extension of
the maturity date of the Credit Facility from April 4, 2012 to April 4, 2013.

The
amounts we can borrow under the terms of our Credit Facility are reduced by the principal amount of our commercial paper issuances and the balance of our letters of credit
outstanding. At June 30, 2008, we had $250 million outstanding under our Credit Facility at a weighted average interest rate of 2.86% and letters of credit totaling
$297.4 million. At June 30, 2008, we could borrow $602.6 million under the terms of our Credit Facility, determined as follows:

June 30,
2008(in millions)Total credit available under Credit Facility

$
1,250.0Less: Amounts outstanding under Credit Facility


(250.0
)Balance of letters of credit outstanding


(297.4
)Principal amount of commercial paper issuances


(100.0
)Total amount we could borrow at June 30, 2008

$
602.6


Commercial Paper Program

At June 30, 2008, we had $100 million in principal amount of commercial paper outstanding, with unamortized discount of
$0.2 million, at a weighted average interest rate of 3.09%, before the effect of our interest rate hedging activities. Under our commercial paper program, we had net repayments of approximately
$168.6 million during the six months ended June 30, 2008, which include gross issuances of $1,025.8 million and gross repayments of $1,194.4 million. At June 30,
2008, we could issue an additional

36

---



$500 million
in principal amount under our commercial paper program. The commercial paper we can issue is limited by the credit available under our Credit Facility.

EUS Credit Agreement

In addition to our Credit Facility and commercial paper program, we have access to an unsecured three year revolving credit agreement
with Enbridge (U.S.) Inc., a wholly-owned subsidiary of Enbridge Inc. (the "EUS Credit Agreement"). The EUS Credit Agreement provides us with access to an additional $500 million
of financing on substantially the same terms as our Credit Facility and matures in December 2010. The amounts available to us under the EUS Credit Agreement remain undrawn at June 30, 2008 and
available for our use.

Cash Requirements for Future Growth

Capital Spending

We expect to make significant expenditures during the next three years for the construction of additional natural gas and crude oil
transportation infrastructure. In 2008, we expect to spend approximately $1.7 billion on these and other projects with the expectation of realizing additional cash flows as projects are
completed and placed in service. As of June 30, 2008, we have approximately $562.6 million in outstanding purchase commitments for materials and services associated with our capital
projects for the construction of assets that we expect to settle during the remainder of 2008. However, we will incur additional commitments as our capital projects continue to progress.

Forecasted Expenditures

We categorize our capital expenditures as either core maintenance or enhancement expenditures. Core maintenance expenditures are those
expenditures that are necessary to maintain the service capability of our existing assets and include the replacement of system components and equipment which is worn, obsolete or completing its
useful life. Enhancement expenditures improve the service capability of our existing assets, extend asset useful lives, increase capacities from existing levels, reduce costs or enhance revenues, and
enable us to respond to governmental regulations and developing industry standards.

We
estimate our capital expenditures based upon our strategic operating and growth plans, which are also dependent upon our ability to produce or otherwise obtain the capital necessary
to accomplish our growth objectives. The following table sets forth our estimates of capital required for system enhancement and core maintenance expenditures through December 31, 2008.
Although we anticipate making the indicated expenditures, these estimates may change due to factors beyond our control, including weather-related issues, construction timing, changes in supplier
prices or poor economic conditions. Additionally, estimates may change as a result of decisions made at a later date to revise the scope of a project. We made capital expenditures of
$672.1 million, including $32.1 million for core maintenance activities, during the six months ended June 30, 2008.

For
the full year of 2008, we anticipate our capital expenditures to approximate the following in billions:

System enhancements

$
0.6Core maintenance activities


0.1Southern Access expansion


0.8Alberta Clipper


0.2$
1.7


37

---



Major Construction Projects

The following table includes our active major construction projects and additional information regarding our estimated construction
cost, actual expenditures through June 30, 2008, the incremental capacity that will become available upon completion of the project and the periods during which we expect to complete the
construction. The projected amounts included in this table may change due to modifications of the scope of the project, increases in materials and construction costs and other factors that are outside
of our direct control.

Capital Expenditures

Estimated Incremental CapacityEstimated
Total Cost

Actual
Expenditures
through
June 30,
2008

Storage(1)

Oil(2)

Natural Gas(3)

Expected Completion(in billions)Southern Access expansion (Lakehead)

$
2.1

$
1.5





400




2009Clarity (East Texas)


0.6


0.6








700

2008Alberta Clipper


1.2








450




Mid-2010North Dakota phase VI expansion


0.2








50




Early 2010Griffith and Superior storage tanks


0.1





1,220







2008Total

$
4.2

$
2.1


1,220


900


700


---

Including major expansion projects and excluding acquisitions, ongoing capital expenditures are expected to be significant over the next three
years due to our Southern Access expansion and Alberta Clipper projects. Core maintenance capital is also anticipated to increase over that period of time due to growth in our pipeline systems and
aging of infrastructure.

We
anticipate funding the system enhancement capital expenditures temporarily through the issuance of commercial paper and borrowing under the terms of our Credit Facility, with
permanent debt and equity funding being obtained when appropriate. Core maintenance expenditures are expected to be funded by operating cash flows.

We
expect to incur continuing annual capital and operating expenditures for pipeline integrity measures to ensure both regulatory compliance and to maintain the overall integrity of our
pipeline systems. Expenditure levels have continued to increase as pipelines age and require higher levels of inspection or maintenance; however, these are viewed to be consistent with industry
trends.

Derivative Activities

We use derivative instruments (i.e., futures, forwards, swaps, options and other financial instruments with similar
characteristics) to mitigate the volatility of our cash flows and manage the risks associated with market fluctuations in commodity prices. Based on our risk management policies, all of our derivative
instruments are employed in connection with an underlying asset, liability or anticipated transaction and are not entered into with the objective of speculating on commodity prices.

38

---



The
following table provides summarized information about the timing and expected settlement amounts of our outstanding commodity derivative instruments at June 30, 2008:

Notional

2008

2009

2010

2011

2012

2013

Total(in millions)SwapsNatural gas(1)


371,502,040

$
(25.2
)
$
(57.9
)
$
(56.3
)
$
(45.5
)
$
(8.3
)
$
(0.4
)
$
(193.6
)NGL(2)


8,963,909


(106.0
)

(110.7
)

(30.6
)

(9.3
)

(1.3
)




(257.9
)Crude(2)


1,483,146


(21.7
)

(24.5
)

(18.2
)

(13.8
)

(11.3
)

(0.7
)

(90.2
)Options-calls























Natural gas(1)


1,279,000


(1.7
)

(2.9
)

(2.4
)

(2.1
)







(9.1
)Options-puts























Natural gas(1)


1,462,000


0.1

















0.1NGL(2)


967,461


0.1


0.1


1.2


1.0


1.8





4.2Totals




$
(154.4
)
$
(195.9
)
$
(106.3
)
$
(69.7
)
$
(19.1
)
$
(1.1
)
$
(546.5
)


---

Operating Activities

Net cash provided by operating activities for the six months ended June 30, 2008 was $273.7 million, an increase of
$15.0 million from the $258.7 million generated during the same period in 2007. The increase in operating cash flow is directly attributable to the improved operating performance of our
Liquids and Natural Gas systems. Although net cash provided by operating activities increased, cash flows associated with changes in our working capital accounts for the six months ended
June 30, 2008 were lower than the same period of 2007 due to higher commodity prices and the general timing differences in the collection on and payment of our current and related party
accounts.

Investing Activities

We used $87.1 million less in our investing activities during the six months ended June 30, 2008 in relation to the same
period in 2007. The decrease is attributable to the $91.4 million reduction of monies spent in the first six months of 2008 on our construction projects as
compared to amounts spent during the same period of 2007. The decrease in the monies spent on our construction projects is primarily attributable to completion of our Clarity project and the first
stage of our Southern Access expansion project.

Financing Activities

Net cash provided by financing activities during the six months ended June 30, 2008 was $556.4 million, compared with
$466.5 million for the corresponding period in 2007. The increase in cash provided by financing activities is attributable to the following:



39

---





The
increase in cash raised from both our unit and debt issuances is partially offset by the following:



For
the six months ended June 30, 2008 we had gross borrowings of $1,715.0 million under our Credit Facility and gross repayments of $1,865.0 million, including
$410.0 million of non-cash borrowings and repayments. Under our commercial paper program we had gross issuances of $1,025.8 million and gross repayments
$1,194.4 million during the first half of 2008.

OFF-BALANCE SHEET ARRANGEMENTS

We have no significant off-balance sheet arrangements.

SUBSEQUENT EVENTS

Distribution to Partners

On July 28, 2008, the Board of Directors of Enbridge Management declared a distribution payable to our partners on
August 14, 2008. The distribution will be paid to unitholders of record as of August 6, 2008, of our available cash of $108.0 million at June 30, 2008, or $0.990 per common
unit. Of this distribution, $74.8 million will be paid in cash, $13.9 million will be distributed in i-units to our i-unitholder, $18.6 million will be
distributed in Class C units to the holders of our Class C units and $0.7 million will be retained from the General Partner in respect of the i-unit and Class C
unit distributions.

REGULATORY MATTERS

FERC Transportation Tariffs-Liquids

Effective July 1, 2008, we increased our rates for transportation on our Lakehead, North Dakota and Ozark systems in compliance
with the indexed rate ceilings allowed by the FERC. In March 2006, the FERC determined that the Producer Price Index For Finished Goods plus 1.3 percent
(PPI + 1.3 percent) should be the oil pricing index for a five year period ending July 2011. The index is used to establish rate ceiling levels for oil pipeline rate changes. For
our Lakehead system, indexing only applies to the base rates, and does not apply to the SEP II, Terrace and Facilities surcharges. Effective July 2008, we increased the base tariff rates on our
Lakehead system by an average of 8.2 percent to equal the indexed ceiling level allowed under the FERC's indexing methodology. On our Lakehead system, the new average rate for crude oil
movements from the International Border near Neche, North Dakota to Chicago, Illinois is $1.26 per barrel, which reflects a $0.05 per barrel increase over the rates filed effective April 1,
2008. In addition to the rates on our Lakehead system, we increased the transportation rates on our North Dakota and Ozark systems 5.2 percent. The tariff rates for our Lakehead, North Dakota
and Ozark systems are at the ceiling levels allowed under the FERC methodology.

Effective
April 1, 2008, we filed our annual tariff with the FERC to reflect true-ups for the difference between estimates and actual cost and throughput data for the
prior year and our projected costs and throughput for 2008. The projected costs for 2008 include four projects including the first stage of the Southern Access mainline expansion, two Superior and
Griffith terminal tank projects and the Clearbrook Manifold project. This filing increased the average tariff for crude oil movements from the Canadian border to Chicago, Illinois, by approximately
$0.34 per barrel, to an average of approximately $1.21 per barrel. We began to realize revenues in relation to this increased surcharge as crude oil is delivered from our pipeline, generally the month
following the effective date of the tariff.

40

---





OTHER MATTERS

We plan to amend our limited partnership agreement to modify the mechanism by which the capital accounts of all our partners are
maintained when our general partner's incentive distribution rights are considered in determining the fair market value of the Partnership's assets in the event of a follow-on offering of our common
units. We do not expect the amendment to materially change the amount of net taxable income or loss allocated to our unitholders or the economic rights of our unitholders as compared with the
allocations or economic rights of our general partner.

RECENT ACCOUNTING PRONOUNCEMENTS NOT YET ADOPTED

Disclosures about Derivative Instruments and Hedging Activities

In March 2008, the Financial Accounting Standard Board, or FASB, issued Statement No. 161,Disclosures
about Derivative Instruments and Hedging Activities, which is effective for fiscal years and interim periods beginning after November 15, 2008. The statement requires
qualitative disclosures about a company's strategies and objectives for using derivatives, quantitative disclosures about fair value gains and losses on derivatives, and disclosures of
credit-risk-related contingent features in derivative instruments. We do not anticipate adopting the provisions of this pronouncement early. We do not expect our adoption of
this pronouncement to have a material affect on our financial statements other than modifications to our existing derivative disclosures to conform to the requirements set forth in the statement.

Calculation of Earnings Per Unit

In March 2008, the Emerging Issues Task Force, or EITF reached consensus on EITF Issue No. 07-4, Application of the Two-Class Method under FASB Statement
No. 128 to Master Limited Partnerships. The pronouncement prescribes the
manner in which a master limited partnership, or MLP, should allocate and present earnings per unit using the two-class method set forth in FASB Statement No. 128, Earning per Share. Under the
two-class method, current period earnings are allocated to the general partner (including any embedded
incentive distribution rights) and limited partners according to the distribution formula for available cash set forth in the partnership agreement. To the extent the partnership agreement does not
explicitly limit distributions to the general partner, any earnings in excess of distributions are to be allocated to the general partner and limited partners utilizing the distribution formula for
available cash specified in the partnership agreement. When current period distributions are in excess of earnings, the excess distributions are to be allocated to the general partner and limited
partners based on their respective sharing of losses specified in the partnership agreement for the period. EITF 07-4 is to be applied retrospectively for all financial statements
presented and is effective for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those fiscal years. Earlier application is not
permitted. We expect to adopt EITF 07-4 for our quarter ending March 31, 2009. We are currently evaluating the affect this pronouncement will have on our present computation
of earnings per unit.

41

---



Item 3.    Quantitative and Qualitative Disclosures About Market Risk

The following should be read in conjunction with the information presented in our Annual Report on Form 10-K for the
year ended December 31, 2007, in addition to information presented in Items 1 and 2 of this Quarterly Report on Form 10-Q. There have been no material changes to that
information other than as presented below.

Our
net income and cash flows are subject to volatility stemming from changes in commodity prices of natural gas, NGLs, condensate and fractionation margins (the relative price
differential between NGL sales and the offsetting natural gas purchases). Our exposure to commodity price risk exists within our Natural Gas and Marketing segments. To mitigate the volatility of our
cash flows, we use derivative instruments (i.e., futures, forwards, swaps, options and other financial instruments with similar characteristics) to manage the risks associated with market
fluctuations in commodity prices. Based on our risk management policies, all of our derivative instruments are employed in connection with an underlying asset, liability or forecasted transaction and
are not entered into with the objective of speculating on commodity prices.

42

---



The
following tables provides information about our derivative instruments at June 30, 2008 and December 31, 2007, with respect to our commodity price risk management
activities for natural gas and NGLs, including condensate:

At June 30, 2008

At December 31, 2007Wtd. Average Price(2)

Fair Value(3)

Fair Value(3)Commodity

Notional(1)

Receive

Pay

Asset

Liability

Asset

LiabilityContract maturing in 2008SwapsReceive variable/pay fixed

Natural Gas


14,746,544

$
12.54

$
7.76

$
70.1

$


$
7.6

$
(14.5
)NGL


60,000


127.50


87.44


2.4








Receive fixed/pay variable

Natural Gas


13,021,803


6.83


13.19





(82.3
)

10.3


(39.8
)NGL


2,904,072


42.37


80.03





(108.4
)




(98.9
)Crude Oil


275,648


61.68


140.96





(21.7
)




(17.7
)Receive variable/pay variable

Natural Gas


110,035,465


12.71


12.83


13.2


(26.2
)

7.0


(3.5
)OptionsCalls (written)

Natural Gas


184,000


4.31


13.52





(1.7
)




(1.3
)Puts (purchased)

Natural Gas


367,000


13.04


8.90


0.1








NGL


218,129


81.49


46.99


0.1





0.1


Contract maturing in 2009SwapsReceive variable/pay fixed

Natural Gas


15,410,840

$
11.63

$
7.98

$
54.6

$


$
5.5

$
(1.6
)NGL


176,870


84.03


63.69


3.5








Receive fixed/pay variable

Natural Gas


17,836,236


6.30


12.36





(104.9
)

1.2


(41.8
)NGL


3,735,045


46.19


77.80





(114.2
)




(43.6
)Crude Oil


354,625


69.29


140.74





(24.5
)




(7.2
)Receive variable/pay variable

Natural Gas


102,218,673


12.43


12.50


3.8


(11.4
)

2.9


(1.8
)OptionsCalls (written)

Natural Gas


365,000


4.31


12.46





(2.9
)




(1.5
)Puts (purchased)

Natural Gas


365,000


12.46


3.40











NGL


365,000


80.24


42.09


0.1





0.6


Contract maturing in 2010SwapsReceive variable/pay fixed

Natural Gas


2,884,475

$
10.80

$
6.79

$
10.8

$


$
4.4

$
NGL


45,625


66.88


57.63


0.4








Receive fixed/pay variable

Natural Gas


10,048,870


4.40


11.13





(63.1
)




(38.0
)NGL


1,331,155


44.08


69.14





(31.0
)




(13.8
)Crude Oil


332,150


79.29


138.29





(18.2
)




(4.4
)Receive variable/pay variable

Natural Gas


61,625,000


11.15


11.22


0.3


(4.3
)

1.5


(0.7
)OptionsCalls (written)

Natural Gas


365,000


4.31


11.23





(2.4
)




(1.4
)Puts (purchased)

Natural Gas


365,000


11.23


3.40











NGL


172,280


70.85


59.23


1.2








Contract maturing in 2011SwapsReceive variable/pay fixed

Natural Gas


848,505

$
10.73

$
4.19

$
4.9

$


$
3.2

$
Receive fixed/pay variable

Natural Gas


7,955,920


3.63


10.77





(50.6
)




(34.1
)NGL


399,310


41.71


67.85





(9.3
)




(4.3
)Crude Oil


228,125


68.36


136.66





(13.8
)




(3.4
)Receive variable/pay variable

Natural Gas


11,385,000


11.03


11.01


0.6


(0.4
)

0.1


OptionsCalls (written)

Natural Gas


365,000


4.31


10.78





(2.1
)




(1.4
)Puts (purchased)

Natural Gas


365,000


10.78


3.40











NGL


83,220


67.09


63.34


1.0











43

---



At June 30, 2008

At December 31, 2007Wtd. Average Price(2)

Fair Value(3)

Fair Value(3)Commodity

Notional(1)

Receive

Pay

Asset

Liability

Asset

LiabilityContract maturing in 2012SwapsReceive variable/pay fixed

Natural Gas


209,709

$
11.31

$
4.10

$
1.3

$


$
0.9

$
NGL


36,600


64.84


55.58


0.3








Receive fixed/pay variable

Natural Gas


1,456,000


3.57


11.43





(9.9
)




(6.8
)NGL


275,232


61.00


67.72





(1.6
)




Crude Oil


219,600


74.85


136.06





(11.3
)




(1.9
)Receive variable/pay variable

Natural Gas


1,089,000


10.54


10.25


0.3








OptionsPuts (purchased)

NGL


128,832


70.24


66.80


1.8








Contract maturing after 2012SwapsReceive fixed/pay variable

Natural Gas


730,000

$
9.83

$
10.43

$


$
(0.4
)
$


$
Crude Oil


73,000


124.05


136.07





(0.7
)







---

Our credit exposure for over-the-counter derivatives is directly with our counterparty and continues until the maturity or
termination of the contract. When appropriate, valuations are adjusted for various factors such as credit and liquidity considerations.

The
table below summarizes our counterparty credit quality and exposures, in millions of dollars.

Counterparty Credit Quality*

June 30,
2008

December 31,
2007(in millions)AAA

$


$
AA


(352.4
)

(298.3
)A


(193.8
)

(47.2
)Lower than A





Total

$
(546.2
)
$
(345.5
)






44

---





Item 4.   Controls and Procedures

We and Enbridge maintain systems of disclosure controls and procedures designed to provide reasonable assurance that we are able to
record, process, summarize and report the information required in our annual and quarterly reports under the Securities Exchange Act of 1934. Our management has evaluated the effectiveness of our
disclosure controls and procedures as of June 30, 2008. Based upon that evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls and
procedures are effective to accomplish their purpose. In conducting this assessment, our management relied on similar evaluations conducted by employees of Enbridge affiliates who provide certain
treasury, accounting and other services on our behalf. We have not made any changes that materially affected, or are reasonably likely to materially affect, our internal control over financial
reporting during the three months ended June 30, 2008.

45

---





PART IIOTHER INFORMATION

Item 1.    Legal Proceedings

Refer to Part I, Item 1. Financial statements, Note 8, which is incorporated herein by reference.

Item 1A.    Risk Factors

There have been no material changes to our risk factors as previously disclosed in Part I, Item 1A of our Annual Report
on Form 10-K for the fiscal year ended December 31, 2007.

Item 6.    Exhibits

Reference is made to the "Index of Exhibits" following the signature page, which we hereby incorporate into this Item.

46

---





SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its
behalf by the undersigned thereunto duly authorized.

ENBRIDGE ENERGY PARTNERS, L.P.(Registrant)By:

Enbridge Energy Management, L.L.C.
as delegate of
Enbridge Energy Company, Inc.
as General PartnerDate: July 29, 2008

By:

/s/STEPHEN J. J. LETWINStephen J. J. Letwin Managing Director
(Principal Executive Officer)Date: July 29, 2008

By:

/s/MARK A. MAKIMark A. Maki Vice PresidentFinance
(Principal Financial Officer)


47

---





Index of Exhibits

Each exhibit identified below is filed as part of this document. Exhibits not incorporated by reference to a prior filing are
designated by an "*"; all exhibits not so designated are incorporated herein by reference to a previous filing as indicated.

3.1

Certificate of Limited Partnership of the Partnership (incorporated by reference to Exhibit 3.1 to the Partnership's Registration Statement No. 33-43425).3.2

Certificate of Amendment to Certificate of Limited Partnership of the Partnership (incorporated by reference to Exhibit 3.2 to the Partnership's 2000 Form 10-K/A dated October 9, 2001).3.3

Fourth Amended and Restated Agreement of Limited Partnership of the Partnership, dated August 15, 2006 (incorporated by reference to Exhibit 3.1 of our Current Report on Form 8-K dated August 16, 2006).3.4

Amendment No. 1 to the Fourth Amended and Restated Agreement of Limited Partnership of the Partnership dated December 28, 2007 (incorporated by reference to Exhibit 3.1 of our Current Report on Form 8-K dated January 3,
2008).4.1

Form of Certificate representing Class A Common Units (incorporated by reference to Exhibit 4.1 to the Partnership's 2000 Form 10-K/A dated October 9, 2001).4.2

Registration Rights Agreement dated as of April 3, 2008, by and among Enbridge Energy Partners, L.P., Banc of America Securities LLC, Deutsche Bank Securities Inc. and HSBC Securities (USA) Inc. (with respect to the
6.50% Notes due 2018) (incorporated by reference to exhibit 4.4 of our Current Report on Form 8-K dated April 7, 2008).4.3

Registration Rights Agreement dated as of April 3, 2008, by and among Enbridge Energy Partners, L.P., Banc of America Securities LLC, Deutsche Bank Securities Inc. and HSBC Securities (USA) Inc. (with respect to the
7.50% Notes due 2038) (incorporated by reference to exhibit 4.5 of our Current Report on Form 8-K dated April 7, 2008).10.1

Seventh Supplemental Indenture dated as of April 3, 2008 between the Partnership and U.S. Bank National Association, successor to SunTrust Bank, as trustee. (incorporated by reference to Exhibit 4.2 of our Current Report on Form 8-K
dated April 7, 2008).10.2

Eighth Supplemental Indenture dated as of April 3, 2008 between the Partnership and U.S. Bank National Association, successor to SunTrust Bank, as trustee. (incorporated by reference to Exhibit 4.3 of our Current Report on Form 8-K
dated April 7, 2008).31.1*

Certification of Principal Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.31.2*

Certification of Principal Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.32.1*

Certification of Principal Executive Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.32.2*

Certification of Principal Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.


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